The invention relates to treatment of surfaces in wellbores, and further concerns compositions and methods for improving surfaces in wellbores for further operations. The invention particularly concerns the provision of surfaces in wellbores adapted for improved bonding with cement.
The use of oil based or synthetic fluids or muds is common in drilling and in other wellbore operations, for a variety of reasons. The oil based or synthetic fluids generally comprise invert emulsion fluids, where the continuous or external phase is predominantly organic or hydrocarbonaceous in nature and the inverse or internal phase is aqueous. For example, an oil based fluid or drilling mud may comprise one or more mineral and/or synthetic oils containing from 5 to 50 percent by volume of water, based on the total volume of fluid, the water being dispersed as very small droplets, usually less than a micron in diameter in the continuous oil phase. The stability of the invert emulsion is generally maintained by one or more additives present in the fluid, such as emulsifiers, emulsion stabilizing agents, and oil wetting agents.
While oil based fluids provide desired advantages or utility in particular circumstances, and, in some instances, will be the fluid(s) of choice, their advantages must be balanced in the situation against certain disadvantages accompanying their use. For example, use of such fluid(s) can pose difficulties in cementing procedures, or in operations designed for reworking a well. In the case of cementing, for example, a significant difficulty encountered is that the oil based fluid xe2x80x9coil wetsxe2x80x9d or coats wellbore surfaces, as well as casing and pipe run into the wellbore. For simplicity, as used hereinafter, the expressions xe2x80x9cwellbore surfacexe2x80x9d or xe2x80x9cwellbore surfacesxe2x80x9d may be understood to encompass not only formation surface or surfaces extant in the drilled opening or wellbore, but may be taken to include formation surface(s) near the wellbore, such as designed fractures or cavities where gravel packing or other operations may be undertaken, along with the surfaces of equipment, e.g., casing, screens, pipe, etc, as may be present in the wellbore or in the formation near the wellbore.
The xe2x80x9coil wettingxe2x80x9d of the formation surfaces by the oil based or synthetic fluids produces an oily residue or oily xe2x80x9ccakexe2x80x9d which renders the surfaces unsuited for many wellbore operations. For example, because cements utilized in wellbore cementing are formulated with aqueous liquid(s), initiation of cementing operations without removal of or otherwise mitigating the oil wet surfaces may result in poor cement bonding, thus defeating the purpose of the cementing operation. This problem is compounded by the fact that the formation surfaces may be porous and quite different from the non-porous metallic casing or equipment surfaces. Similar difficulties arise in gravel packing operations.
Again, in so-called open-hole reservoirs, production is initiated through the formation wall and screens directly. In such instances, any oil based fluid(s) cake that is not removed before or promptly after initiation of production may impair inflow through either the screens or the formation wall. Maximization of production and reduction of completion hardware damage requires, therefore, that measures be undertaken to reduce or remove the cake.
In the past, oily cake or oily residue has been removed in some cases by using a wash, perhaps from the same oil as the mud, which contained appropriate solvents and a mixture of surfactants. Another approach has employed a water-free mixture of surfactants and an alcohol. In some instances, various solvents, such as xylene, toluene, and low flash point terpenes, have been used. For a variety of reasons, including cost and increasing safety and environmental concerns, one or more of these options may be unattractive in a given case. In other instances, oil based fluid residue removal has not been sufficiently achieved, and, for example, cement bonding with a formation has not been satisfactory. As utilized hereinafter, the expression xe2x80x9coil-containing residuexe2x80x9d is taken to include the oily xe2x80x9ccakexe2x80x9d on the formation surfaces and/or the oily residue left or remaining on equipment, casing, gravel, etc., in or in the formation near the wellbore. The invention addresses the problem of oil-containing residue on wellbore surfaces.
Accordingly, in one embodiment, the invention relates to a novel method or process comprising contacting a wellbore surface with an amount of wellbore fluid composition comprising a terpene composition and wetting surfactant, in an amount sufficient or effective to reduce oil-containing residue from the wellbore surface and water wet wellbore surface. The combination fluid composition supplied in effective amount thus comprises sufficient or effective amount of terpene composition to dissolve oil from the wellbore surface to a desired degree, and an amount of wetting surfactant effective to water wet wellbore surface. As employed herein, xe2x80x9cwater wetxe2x80x9d indicates conditioning of wellbore surface to the extent that water adheres to at least a significant portion of the wellbore surface, as contrasted with oil wet or oil-containing surface which is significantly hydrophobic.
According to the invention, the terpene composition is selected from cyclic terpenes, and mixtures thereof; acyclic terpenes, and mixtures thereof; cyclic terpenoids having one or more benzenoid groups, and mixtures thereof; acyclic terpenoids having one or more benzenoid groups, and mixtures thereof; and mixtures thereof. Commonly available terpenes and terpenoids, many of which are alcohols, may be used, and are generally available in varying degrees of purity, generally available as mixtures. The preferred terpenes are biodegradable monoterpenes, such as d-limonene and alpha-pinene derivatives. In the preferred fluid composition, the terpene composition will be present in an amount of at least 85 percent by weight, more preferably at least 90 percent, and most preferably up to about 99 percent by weight of the blend. Unless otherwise specified or evident from the context, all percentages given herein are by weight, based on the weight of the fluid. The fluid composition may contain, if desired, minor quantities of components such as solvents, etc.
The wetting surfactant will be selected on the basis of capability to achieve the water wet condition mentioned, and the term xe2x80x9csurfactantxe2x80x9d, as utilized herein, is understood to include mixtures of appropriate surface active materials. In general, the wetting surfactant may be selected from anionic, which includes soaps (e.g., sodium stearate) whose active groups are anions; cationic, such as quaternary ammonium compounds; non-ionic, such as alcohol ethoxylates; and Zwitterionic, such as sulfobetaine. Commonly, the concentration in the fluid of the surfactant will range from 0.01 percent to 5 percent, possibly to 10 or 12 percent, preferably 0.1 percent to about 4 percent. The capability of a surfactant to water wet surfaces, such as wellbore surfaces, may be determined by testing, as described herein.
In a preferred aspect, to insure that water wetting of a wellbore surface is achieved to the desired extent, e.g., in the possibility that the surfactant has not water wet the wellbore surface under the wellbore conditions extant, the wellbore surface may further be contacted, after the above-mentioned contacting or treatment, with an aqueous fluid comprising a viscosifying organic polymer and wetting surfactant. This combination will be supplied in an amount sufficient to insure water wetting of the wellbore surface to the extent desired. In this further stage, the aqueous fluid will contain, as indicated, a viscosifying organic polymer (preferably synthetic) which is most preferably a water soluble polymer of an acrylic or methacrylic acid. The surfactant chosen may be the same as that for the first stage or spacer. The combination of the viscosifying polymer and the water wetting surfactant in the aqueous fluid insures effective removal of first stage solution with oil-containing residue and water wets wellbore surfaces. While a wide variety of polymers may be employed, those described in U.S. Pat. No. 4,432,881 to Evani and U.S. Pat. No. 4,429,097 to Chang et al, both patents incorporated herein by reference, are particularly suitable. Generally, the aqueous fluid will contain or comprise from about 0.25 pounds per barrel to about 3.0 pounds per barrel or more of the viscosifying synthetic polymeric material, and from 1 percent to about 12 percent of wetting surfactant. Mixtures of suitable polymers may be employed, and, as indicated, the xe2x80x9csurfactantxe2x80x9d may comprise mixtures, these components being utilized in any and all proportions. Anionic and non-ionic classes of surfactant are preferred.
In a further embodiment, the invention relates to a composition for treating oil-based residue in or on well-bore surfaces comprising a first fluid composition containing a terpene composition and wetting surfactant, in an amount sufficient or effective to reduce oil-containing residues from wellbore surfaces and water wet wellbore surfaces. Additionally, the invention comprises a system for treating oil-based residue in or on wellbore surfaces including the first fluid composition and a second removal fluid comprising an aqueous fluid containing or comprising a viscosifying synthetic organic polymer and surfactant, in an amount sufficient (effective) to water wet wellbore surface.
The invention further comprises fluid compositions or fluids formed by blending, in any order, the required components, and use of such in the methods of the invention. Thus, suitable wellbore fluid compositions may be formed by blending, in any order, a terpene composition and wetting surfactant, in amounts effective to reduce oil-containing residues from a wellbore surface, and sufficient wetting surfactant may be blended to water wet wellbore surface. If desired, a weighting agent may also blended. Preferably, the terpene composition is blended in an amount of at least 85 percent, more preferably at least 90 percent, and most preferably up to about 95 percent by weight of the wellbore fluid composition.
Similarly, the system for reducing oil-containing residue from a wellbore surface may comprise a first wellbore fluid composition formed by blending, in any order, a terpene composition and wetting surfactant, in amounts effective to reduce oil-containing residues from a wellbore surface; and a second removal fluid comprising an aqueous fluid formed by blending a viscosifying organic polymer and wetting surfactant in an amount sufficient to water wet wellbore surface. A weighting agent may also blended with the first wellbore fluid composition and/or the second removal fluid, and the terpene composition may be blended in an amount of at least 85 percent, more preferably at least 90 percent, and most preferably up to about 95 percent by weight of the wellbore fluid composition. The systems so blended may be used in the methods described herein as appropriate.
In the normal case, an effective amount of the first composition may be pumped in the well and contacts the wellbore surface for a time sufficient to reduce oil-based residue. A suitable time may be from about 5 to 20minutes of contact time, although greater or lesser times may be used. Similar times may be used for the second or water wetting stage or spacer. Other embodiments will become apparent from the following detailed description.
The invention lends itself to various approaches, including use of weighted and unweighted embodiments or fluids. In an unweighted version, the method employed may involve a single fluid or spacer, or may comprise two or multiple spacers. For example, the first or single stage fluids composition could contain 85 to 99% of d-limonene and/or other terpene composition, and 1 to 12 or even 15% anionic or non-ionic surfactant, and 0-4% of water. If more than one spacer is used, the second stage spacer or subsequent spacers may comprise aqueous based solutions containing 4-10% surfactant. In a weighted version, the first or single spacer fluid composition may contain 85-99% by wt of d-limonene or similar terpene composition, a surfactant in the range of 1 to 12%, water in the range of 0 to 4%; a viscosifier, e.g., an organophilic clay in the range of 1.0 to 8.0 ppb or, for example, a cross-linked aluminum phosphate ester in the range of 0.25% to 3.0%; and a weighting agent, e.g., barite, to provide a fluid with a density range from 8.5-22 ppg. If employed, the secondary spacer or subsequent spacers of the invention are aqueous based, and contain a synthetic polymeric viscosifier, the surfactant in the concentrations mentioned, and a weighting agent to provide a fluid with a density range from 8.5-22 ppg. Fluid loss additives may also be added to this spacer. Optionally, prior to the aqueous based fluid, a sweep fluid or composition, such as brine, may be utilized.
In a further aspect of the invention, in an open-hole reservoir, the chosen completion design requires change to a water based fluid after drilling the well with oil based or synthetic based mud. However, contact between an aqueous fluid and the oil based or synthetic based fluid, which contains surfactant and other potentially emulsifying components, may lead to emulsification. This emulsification may then lead to high viscosity fluids, which may cause hydraulic fracturing of the well. Ideally, the open-hole is displaced to brine with a neutralizing spacer in between. The first and/or spacer treatment of the invention may be employed as an appropriate spacer.
Accordingly, potential uses of the method and system of the invention include a number of clean-up situations in open-hole reservoirs. For example, the invention may be used for clean-up of oil-based mud from the reservoir section of the well, which is to be completed without casing string of cement. The invention may be used to displace oil-based or synthetic based mud to a brine or base-oil in an open-hole reservoir, or to displace oil-based or synthetic based mud to a brine, base-oil, or viscosified completion fluid before or after running a sand control screen downhole. The invention may be employed in displacing oil-based or synthetic based mud to a brine before gravel-packing the well using a water-based gravel-pack carrier fluid. This displacement can either take place with or without screen in the well.
In further aspects, the invention may be used in reducing oil-containing residue that is impairing hydrocarbon production after completing the open-hole reservoir; in reducing or removing oil-containing residue that is impairing hydrocarbon production after gravel-packing the open-hole reservoir either with a water-based or an oil-based gravel pack carrier; and in reducing or removing oil-containing residue from screens that is impairing production.
In some instances, a wellbore fluid composition having a greater flash point will be desired. In such cases, a quantity of a suitable or compatible liquid may be blended to provide a fluid composition having an increased flash point. Suitable liquids may include the oil or synthetic base fluids utilized in formulation of oil-based fluids or synthetic based fluids, as well as other suitable organic fluids, in limited quantities. For example, a higher flash point wellbore composition might contain up to 70 percent of the oil used for the oilbased fluid. Accordingly, where flash point is of concern, a suitable wellbore fluid composition according to the invention may comprise the terpene composition and the surfactant in an amount sufficient to reduce oil-containing residues from wellbore surfaces. Preferably, the fluid composition will comprise about 25% to about 90 percent of the terpene composition, 1 to 5 percent surfactant, and 5 percent to 70 percent of the oil or synthetic base.
According to the invention, a repeatable methodology has been developed to determine mud removal from both metallic and porous media. Experiments indicate that the ability to remove diesel, oil or synthetic fluids varies depending on the base fluid used. Base fluids listed as equivalents also vary widely. Escaid 110 fluids and enhanced mineral oils, are difficult to remove. D-limonene is the most effective solvent. A combination of D-limonene and surfactant in a single spacer is the preferred removal composition of the invention. In many cases, cleaned surfaces are left water wet. Traces of mud left may still be oil wet. This is also true of wall cake. A secondary surfactant spacer may be used to water wet residual mud or cake.
Weighted spacers may behave differently from those which are unweighted. Where barite is used as a weighting agent, coating of barite on the test metal or tile surfaces may occur. This occurred where the surfactant was added to D-limonene or used as a secondary spacer. Therefore a balance has to be found between water wetting capability and barite coating out on surfaces.